Multi-stage Treatment System with Work String Mounted Operated Valves Electrically Supplied from a Wellhead

ABSTRACT

A lower completion for open or cased hole is delivered on a work string. Electric power extends from a remote location past a production packer and to an array of electrically operated sleeves alternating with packers. An inductive coupling or wet connect allows the work string to release from the production packer and a production string tagged into the production packer for continued operation of the sliding sleeves. In the event of an incipient screenout a different sliding sleeve can be opened quickly or a sliding sleeve near hole bottom can be opened to maintain flow. The sliding sleeves can be directly or indirectly operated with electric power from a surface or wellhead location that is above the production packer. A wet connect or inductive coupler allows removal of the work string and replacement with a production string for continuing functionality of the sliding sleeves.

FIELD OF THE INVENTION

The field of the invention is multistage treatment systems and more particularly where the lower completion is run in with a work string and power is supplied to valves from a remote location along the work string to valves and associated packer(s) for isolation.

BACKGROUND OF THE INVENTION

Stage treatment systems have used sliding sleeve valves that are sequentially operated to open with balls of progressively larger diameters landed sequentially in a bottom up direction for stage treatment of an interval. For large intervals a large number of balls that vary little in size are needed. At the end of the treatment the seats and balls can be milled up for production leaving the sliding sleeves in which the seats were supported behind. In some cases the balls could be made of a disintegrating material as well as the seats to avoid a milling trip in the hole.

Other ways of actuating sliding sleeves have been proposed. Some of them involved stored electric power at each sliding sleeve that is triggered remotely such as with a field generated from an object dropped into the borehole. Other devices relied on hydrostatic pressure on one side of a piston referenced on an opposed side to a low pressure chamber and a trigger mechanism to enable piston movement taking advantage of the pressure differential on the piston to move a sliding sleeve once. Some designs duplicated the opposed chamber design on one or more pistons so that a given sliding sleeve could be shifted in opposed directions at least once. These systems were rather bulky and complex and in some installations there was insufficient physical space to deploy the needed components to get multiple movements.

To date a practical solution for electrically powered sliding sleeves with electric power coming from a surface or wellhead location has not been proposed. The present invention addresses such a system where a work string supports a lower completion and power comes down the work string to an array of electrically powered sliding sleeve valves alternating with packers. The sleeves can be directly or indirectly electric powered. Direct powering is by using an electric motor and indirect powering is by running a hydraulic pump with the supplied electric power and actually moving the sliding sleeve with developed hydraulic pressure.

An electric cable runs the length of the work string to a separable connection such as an inductive coupler or a wet connect. The electric cable continues past a production packer that stays in the hole and continues to each of the sliding sleeves that stay in the hole with the lower completion. Treatment in any sequence is possible as well as rapid change from one interval to another in the event of an incipient “screen out” where the formation stops taking solids such as a proppant during a fracturing job. A dump zone valve is provided near hole bottom to redirect slurries in the event of a screenout to prevent clogging the borehole. After all the intervals that need treatment are treated the work string releases from the lower completion above the set production packer at the inductive coupling or the wet connect. The work string is removed and a production string with the upper portion of the inductive coupling or the wet connect is run back in. The production string can have accessory conduits such as chemical injection lines, control lines and an upper portion of the electric cable that was also on the work string. The lower assembly can have sensors in isolated intervals by the packers on the work string to send well data to the surface through the inductive coupler or wet connect. The same data transmission capability is retained when the production string replaces the work string. These and other features of the present invention will be more readily apparent to those skilled in the art from a review of the description of the preferred embodiment and the associated drawings while recognizing that the full scope of the invention is to be determined by the scope of the appended claims.

Relevant to the present invention are U.S. Pat. No. 9,404,340; WO2016126261 and EP 2636844.

SUMMARY OF THE INVENTION

A lower completion for open or cased hole is delivered on a work string. Electric power extends from a remote location past a production packer and to an array of electrically operated sleeves alternating with packers. An inductive coupling or wet connect allows the work string to release from the production packer and a production string tagged into the production packer for continued operation of the sliding sleeves. In the event of an incipient screenout a different sliding sleeve can be opened quickly or a sliding sleeve near hole bottom can be opened to maintain flow. The sliding sleeves can be directly or indirectly operated with electric power from a surface or wellhead location. A wet connect or inductive coupler allows removal of the work string and replacement with a production string for continuing functionality of the sliding sleeves.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic elevation view of the lower assembly delivered on a work string;

FIG. 2 shows the view of FIG. 1 with the work string removed;

FIG. 3 is the view of FIG. 2 with the production string connected to the lower completion.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

FIG. 1 illustrates a work string 10 supporting a production packer 12 and a lower completion that comprises a plurality of sliding sleeve valves 14 separated by a packer 16 on at least one side to allow an interval 18 of an open hole bore 20 to be isolated. Although only intervals 18, 22 and 24 are shown, those skilled in the art will appreciate that additional intervals and packers 16 can be used. The lower completion has an electrical conductor 28 that runs from lower end 26 at a dump zone sleeve 32 to an upper end 30 at inductive coupler lower portion 34. Those skilled in the art will appreciate and a downhole wet connect of a type known in the art can be used in place of the inductive coupler lower portion 34 and mating upper portion 36. Conductor 38 extends from inductive coupler upper portion 36 through a feed-through slick joint 40 that is positioned in a blowout preventer 42 that has rams 44 for sealing the annulus 46. Conductor 38 goes to a platform or a surface location so that in FIG. 1 there is supplied electric power from the surface or platform to the sliding sleeve valves 46 and the dump zone sliding sleeve 32 near a float shoe 48. Float shoe 48 is open for circulation when running in but can be isolated to allow the work string to be pressured internally to set the production packer 12 and interval defining packers 16. Between each pair of interval defining packers 16 is an array of sensors/transmitters 50 connected by cable 52 that extends through the production packer 12 and to lower portion 34 of the inductive coupler. Cable 54 runs from the upper portion 36 of the inductive coupler past the blowout preventer 42 and to a platform or the surface where the transmitted data can be processed, stored or displayed for operating personnel.

FIG. 2 shows the work string down to the lower portion 34 of the inductive coupler, removed and FIG. 3 shows a production string 56 that includes cables 54 and 38 as well as an upper portion 36 of the inductive coupler positioned in production packer 12 in a manner that a seal assembly (not shown) lands in seal bore housing 58 and is latched in position. A chemical injection line 60 extends to injection mandrel 62 which is part of the production string 56. Selected sleeves 16 can then be opened for production or injection service. Selected sleeves 16 can also be closed if an interval is producing water or other undesirable fluids.

There are several noteworthy features. The system delivers a lower completion on a work string where power is delivered from a remote location such as a surface or a platform and the work string is removable in favor of a production string that reconnects electric power to the sleeves 16 or the dump zone sleeve 32. Having multiple sleeve that can be quickly opened when treating one zone is an advantage if there is a developing screenout. In that event, another sleeve 16 can be opened to keep the flow moving or, preferably, the dump zone sleeve 26 can be opened to keep the treatment slurry moving to a location of less or no interest in the borehole to avoid totally plugging the lower completion in the event of a screenout. This is preferred to opening another sleeve 16 as a screenout looks imminent because neither the zone being treated at the time nor a different zone where another sleeve 16 is opened will get properly fractured or treated. Sleeves 16 or 32 can be directly powered electrically such as by operating an electric motor or they can be indirectly powered by electricity such as by operating a hydraulic pump and using hydraulic pressure to shift the sleeve. With the power provided remotely, each valve can be simply operated open and closed multiple times with a pair of electric motors or one that can be reversed or hydraulic valving to direct pressure to above or below a piston to get the sleeve moving in one of two opposed directions. There is no milling out needed and production can begin right after the treatment ends and the work string removed and replaced with the production string. To the extent it may be cost effective to save a trip in the hole to replace the work string with the production string, the production string can be run in initially without safety valves which can then be inserted after the treatment. The sleeves 16 can have two movements to open a clear port for treatment and then to be moved again to open a screened port for production. Alternatively two sleeves can be used with a first opening an unobstructed port and the second opening a screened port as the first sleeve is closed over the treatment port. After the treatment ends a tree is installed with the production string 56. The valves 16 and 32 are schematically illustrated to include an electric motor driver for direct operation or to include an electric driven hydraulic pump and valving to opposed sides of an actuating piston for the valves so that the valves can be moved in opposed directions multiple times in a bottom up or top down or random order.

The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.

The above description is illustrative of the preferred embodiment and many modifications may be made by those skilled in the art without departing from the invention whose scope is to be determined from the literal and equivalent scope of the claims below: 

I claim:
 1. A borehole treating method, comprising: providing electric power to a plurality of lower completion valves from uphole of a production packer supporting a lower completion, said production packer supported by a work string; operating said valves with said provided electric power for selective formation access from the lower completion to perform a treatment.
 2. The method of claim 1, comprising: replacing said work string with a production string after said treatment; continuing to provide electric power to said valves from uphole of the production packer along the production string; operating said valves in aid of production from the formation.
 3. The method of claim 2, comprising: isolating said valves in discrete isolated intervals using packers.
 4. The method of claim 2, comprising: engaging and releasing said lower completion from said work string with an inductive coupler or wet connect.
 5. The method of claim 2, comprising: engaging said production string to said lower completion with an inductive couple or a wet connect.
 6. The method of claim 4, comprising: connecting said valves with a valve cable to a lower portion of said inductive coupler or said wet connect; extending said cable from an upper portion of said inductive coupler or said wet connect past said production packer and further uphole.
 7. The method of claim 3, comprising: providing at least one sensor to transmit well data to above said production packer from each said interval on a data cable, said data cable extending to an inductive coupler or wet connect and further uphole on said work string; disconnecting said data cable at said inductive coupler or wet connect when removing said work string; reconnecting said data cable at said inductive coupler or wet connect when producing with said production string.
 8. The method of claim 6, comprising: removing said upper portion of said inductive coupler or wet connect with a part of said valve cable when disconnecting said work string from said lower completion; replacing said upper portion of said inductive coupler or wet connect with said part of said valve cable when connecting said production string to said lower portion of said inductive coupling or wet connect.
 9. The method of claim 1, comprising: providing sliding sleeves as said lower completion valves.
 10. The method of claim 1, comprising: locating at least one of said completion valves in an isolated interval to a portion of a formation that is not of production interest; opening said at least one completion valve in the event a screenout is detected.
 11. The method of claim 1, comprising: opening more than a single said completion valve at a time in the event a screenout is detected.
 12. The method of claim 1, comprising: using said provided electric power to directly operate said lower completion valves with an electric motor in opposed directions multiple times.
 13. The method of claim 1, comprising: using said provided electric power to indirectly operate said lower completion valves by producing hydraulic pressure to opposed sides of an actuating piston for said lower completion valves.
 14. The method of claim 1, comprising: opening said lower completion valves in an uphole or downhole direction sequentially or in a random order.
 15. The method of claim 1, comprising: locating said lower completion in open hole.
 16. The method of claim 1, comprising: locating said lower completion in cased hole.
 17. The method of claim 1, comprising: performing fracturing as said treatment. 